Nitrogen rejection methods and systems

ABSTRACT

Methods and systems for removing nitrogen from a natural gas feed stream. The systems and methods generally include a heat exchange unit, a separation unit, and a liquid methane pump unit, where the separation unit produces a liquid methane bottoms stream and a gaseous overhead stream enriched in nitrogen and the liquid methane pump unit compresses the liquid methane bottoms stream and then pumps the stream through the heat exchange unit to cool a natural gas feed stream. In some embodiments the liquid methane pump unit is a sleeve bearing type unit. Beneficially, the disclosed systems and methods incorporate high head pumps for liquid methane compression instead of vaporizing the liquid methane and compressing it in a gaseous compression units that are typically used for this purpose, saving space, materials, and power.

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional Application No. 61/178,328 filed May 14, 2009.

FIELD OF THE INVENTION

Embodiments of the disclosed invention relate to nitrogen rejection methods and systems. More particularly, embodiments of the disclosed invention relate to methods and systems for efficiently reducing the nitrogen concentration of a natural gas production stream.

BACKGROUND OF THE INVENTION

This section is intended to introduce various aspects of the art, which may be associated with exemplary embodiments of the present disclosure. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present disclosure. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.

Description of the Related Art

Natural gas is one of the world's fastest growing and most significant sources of energy. It is highly desirable due to it's availability, relative price, and its reduced environmental impact over coal and other sources of energy generation. Gas fields, some containing recoverable hydrocarbon condensates and/or C2, C3, C4, and C5 natural gas liquids (NGL) components, face the challenge of separating nitrogen from the methane-rich stream in order to meet the energy content (often measured in BTU/scf) requirements for methane gas sales contracts. The separation of nitrogen from methane is technically challenging because the gases have similar size, chemical nature, and boiling point. The additional complexity of nitrogen separation and the compression normally associated with nitrogen removal from methane-rich streams combine to increase the area footprint and weight of the facilities involved. Efficiently reducing the nitrogen content of produced natural gas streams is one of the world's toughest energy challenges.

In a standard cryogenic distillation process used for high flow rate applications, the natural gas feed stream is routed repeatedly through a column and a heat exchanger (typically a brazed aluminum plate-fin type), where the nitrogen is cryogenically separated and vented. This approach is very capital intensive as a lot of aluminum is needed. Further, the final methane product is typically produced at low pressure, so re-pressurization is needed, which is almost always accomplished via energy-intensive compressors. Other existing processes include pressure swing adsorption (PSA), membrane separation, lean oil absorption, and solvent absorption.

Existing cryogenic distillation processes require large, expensive, complex pieces of equipment to reduce the nitrogen (N₂) content of produced natural gas. In particular, existing cryogenic distillation nitrogen rejection units (NRU's) also require large quantities of aluminum for fabrication. Another problem with current processes is the significant amount of energy required to compress the methane up to a sufficient pressure for pipeline transport to the destination market.

NRU processes other than cryogenic distillation also generally result in large capital expenditure, complexity, and high power consumption costs due to the needed compression and other factors.

One example of a common cryogenic nitrogen rejection approach is found in U.S. Pat. No. 7,520,143 (the '143 patent), which discloses a dual stage cryogenic distillation type nitrogen rejection unit (NRU) that produces a low pressure, low temperature liquefied natural gas stream having less than 1.5 mol % nitrogen, a nitrogen vent stream having over 98 mol % nitrogen content, and a fuel stream with a nitrogen content of about 30 mol %.

What is needed are methods and systems of more efficiently separating nitrogen from natural gas in natural gas production operations.

Other relevant information may be found in U.S. Pat. No. 4,890,988; COYLE, DAVID A., PATEL, VINOD, Processes and Pump Services in the LNG Industry, Proceedings of the Int'l Pump Users Symposium (2005); and “Rejection Strategies,” Hydrocarbon Engineering, October 2007 pp. 49-52.

SUMMARY OF THE INVENTION

In one embodiment of the present invention a nitrogen rejection system is provided. The nitrogen rejection system includes a natural gas feed stream comprising nitrogen and methane and having a temperature above cryogenic conditions; a feed stream heat exchanger configured to reduce the temperature of the natural gas feed stream to form a majority liquefied natural gas feed stream; a separation unit configured to receive the cooled natural gas feed stream and produce an overhead stream enriched in nitrogen and a bottoms stream enriched in methane (“liquefied methane stream”); and a liquid methane pump configured to pump the liquefied methane stream to a sales compression pressure to form a pressurized liquefied methane stream, wherein the pressurized liquefied methane stream is substantially vaporized in the feed stream heat exchanger to form a methane product stream. In some embodiments, the liquid methane pump is a sleeve bearing type pump and may further include a magnetic thrust bearing configured to reduce a gravity thrust load on an axial bearing of the liquid methane pump and may be configured as a single pump, a series of at least two pumps, a parallel configuration of at least two pumps, a multistage pump, and any combination thereof.

In some embodiments, the separation unit is configured to operate at a pressure of at least about 200 pounds per square inch (psi) to about 500 psi and a temperature of at least about −220 degrees Fahrenheit (° F.) to about −120° F. and may be a tower having a top feed stripper portion and a lower cryogenic reboiler portion configured to separate gaseous nitrogen from the liquefied methane stream. In additional embodiments, at least a portion of the overhead stream enriched in nitrogen is fed to the feed stream heat exchanger to form a warmed nitrogen enriched stream. The system may further include a compressor configured to compress the warmed nitrogen enriched stream to form a compressed nitrogen enriched stream; and a nitrogen rejection unit (NRU) configured to receive the compressed nitrogen enriched stream to form a methane enriched stream, wherein the warmed nitrogen stream is less than about 50 volume percent (vol %) of the natural gas feed stream. Alternatively, a portion of the overhead stream enriched in nitrogen may be fed to a power generation unit configured to generate power using the at least a portion of the overhead stream enriched in nitrogen.

In still another alternative embodiment of the system, the system further includes a reboiler feed stream from the separation unit; a slip stream from the substantially liquefied natural gas feed stream; a reboiler heat exchanger configured to exchange heat energy from the slip stream to the reboiler feed stream to generate a nitrogen containing vapor from the reboiler feed stream, wherein the slip stream is then re-mixed with the substantially liquefied natural gas feed stream; and an expansion device configured to receive the substantially liquefied natural gas feed stream and hold a back-pressure on a feed condensing pass of the feed stream heat exchanger, wherein the expansion device is selected from the group consisting of a flow control device, a level control device, a back-pressure control valve, and any combination thereof. Alternatively, the system may include a feed separator configured to produce a nitrogen enriched gas stream and a bottoms stream enriched in methane; and at least one level control valve configured to maintain a liquid level in the feed separator. In a further embodiment, the system may include a flow integrated controller configured to control at least the back-pressure on the feed condensing pass of the feed stream heat exchanger.

In a second major embodiment of the disclosure, a method of nitrogen rejection is disclosed. The method includes cooling a natural gas feed stream comprising nitrogen and methane in a feed stream heat exchanger to form a majority liquefied natural gas feed stream; separating the substantially liquefied natural gas feed stream in a separator to produce an overhead stream enriched in nitrogen and a liquid bottoms stream enriched in methane (“liquefied methane stream”); pressurizing the liquefied methane stream in a liquid methane pump to a sales compression pressure to form a pressurized liquefied methane stream; and exchanging heat from the natural gas feed stream to the pressurized liquefied methane stream in the feed stream heat exchanger to form a methane product stream. In some embodiments, the liquid methane pump is a sleeve bearing type pump and further comprises a magnetic thrust bearing configured to reduce a gravity thrust load on an axial bearing of the liquid methane pump, which may be configured as a single pump, a series of at least two pumps, a parallel configuration of at least two pumps, a multistage pump, or any combination thereof.

Additional embodiments may provide that the separation unit is configured to operate at a pressure of at least about 200 pounds per square inch (psi) to about 500 psi and a temperature of at least about −220 degrees Fahrenheit (° F.) to about −120° F. or that the separation unit is a tower having a top feed stripper portion and a lower cryogenic reboiler portion configured to separate gaseous nitrogen from the liquefied methane stream. The method may further include feeding at least a portion of the overhead stream enriched in nitrogen to the feed stream heat exchanger to form a warmed nitrogen enriched stream, compressing the warmed nitrogen enriched stream in a compressor to form a compressed nitrogen enriched stream; and feeding the compressed nitrogen enriched stream to a nitrogen rejection unit (NRU) to form a methane enriched stream, wherein the warmed nitrogen stream is less than about 50 volume percent (vol %) of the natural gas feed stream.

In a further alternative embodiment, the method may include feeding at least a portion of the overhead stream enriched in nitrogen to a power generation unit; and generating power in the power generation unit.

In yet another alternative embodiment, the method may include taking a reboiler feed stream from the separation unit; taking a slip stream from the substantially liquefied natural gas feed stream; exchanging heat energy from the slip stream to the reboiler feed stream in a reboiler heat exchanger to generate a nitrogen containing vapor from the reboiler feed stream; re-mixing the slip stream with the substantially liquefied natural gas feed stream; and maintaining a back-pressure on a feed condensing pass of the feed stream heat exchanger using an expansion device configured to receive the substantially liquefied natural gas feed stream, wherein the expansion device is selected from the group consisting of a flow control device, a level control device, a back-pressure control valve, and any combination thereof.

In still another alternative, the method may include producing a nitrogen enriched gas stream and a bottoms stream enriched in methane in a feed separator; and maintaining a liquid level in the feed separator using a level control valve. The method may further provide for controlling at least the back-pressure on a feed condensing pass of the feed stream heat exchanger and the back-pressure on the separation unit using flow integrated controller.

BRIEF DESCRIPTION OF THE DRAWINGS

The foregoing and other advantages of the present invention may become apparent upon reviewing the following detailed description and drawings of non-limiting examples of embodiments in which:

FIG. 1 is a schematic illustration of a system in accordance with certain aspects of the disclosure;

FIG. 2 is a flow chart illustrating of a process in accordance with certain aspects of the system of FIG. 1;

FIGS. 3A-3C are schematics of several exemplary alternative embodiments of the system of FIG. 1;

FIG. 4 illustrates a chart showing a temperature heat flow plot for comparing heat flow between hot and cold streams.

DETAILED DESCRIPTION

In the following detailed description section, the specific embodiments of the present disclosure are described in connection with preferred embodiments. However, to the extent that the following description is specific to a particular embodiment or a particular use of the present disclosure, this is intended to be for exemplary purposes only and simply provides a description of the exemplary embodiments. Accordingly, the disclosure is not limited to the specific embodiments described below, but rather, it includes all alternatives, modifications, and equivalents falling within the true spirit and scope of the appended claims.

Definitions

Various terms as used herein are defined below. To the extent a term used in a claim is not defined below, it should be given the broadest definition persons in the pertinent art have given that term as reflected in at least one printed publication or issued patent.

As used herein, “a” or “an” entity refers to one or more of that entity. As such, the terms “a” (or “an”), “one or more”, and “at least one” can be used interchangeably herein unless a limit is specifically stated.

As used herein, the term “enriched” as applied to any stream withdrawn from a process means that the withdrawn stream contains a concentration of a particular component that is higher than the concentration of that component in the feed stream to the process.

As used herein, the term “expansion device” refers to one or more devices suitable for reducing the pressure of a fluid in a line (for example, a liquid stream, a vapor stream, or a multiphase stream containing both liquid and vapor). Unless a particular type of expansion device is specifically stated, the expansion device may be (1) at least partially by isenthalpic means, or (2) may be at least partially by isentropic means, or (3) may be a combination of both isentropic means and isenthalpic means. Suitable devices for isenthalpic expansion of natural gas are known in the art and generally include, but are not limited to, manually or automatically actuated throttling devices such as, for example, valves, control valves, Joule-Thomson (J-T) valves, or venturi devices. Suitable devices for isentropic expansion of natural gas are known in the art and generally include equipment such as expanders or turbo expanders that extract or derive work from such expansion. Suitable devices for isentropic expansion of liquid streams are known in the art and generally include equipment such as expanders, hydraulic expanders, liquid turbines, or turbo expanders that extract or derive work from such expansion. An example of a combination of both isentropic means and isenthalpic means may be a Joule-Thomson valve and a turbo expander in parallel, which provides the capability of using either alone or using both the J-T valve and the turbo expander simultaneously. Isenthalpic or isentropic expansion can be conducted in the all-liquid phase, all-vapor phase, or mixed phases, and can be conducted to facilitate a phase change from a vapor stream or liquid stream to a multiphase stream (a stream having both vapor and liquid phases). In the description of the drawings herein, the reference to more than one expansion device in any drawing does not necessarily mean that each expansion device is the same type or size.

As used herein, the term “indirect heat exchange” means the bringing of two fluids into heat exchange relation without any physical contact or intermixing of the fluids with each other. Core-in-kettle heat exchangers and brazed aluminum plate-fin heat exchangers are specific examples of equipment that facilitate indirect heat exchange.

As used herein, the term “compressor” means a machine that increases the pressure of a gas by the application of work.

As used herein, the term “liquid methane pump” means a device for increasing the head of a fluid stream at cryogenic conditions. More specifically, the liquid methane pump is limited to the types of pumps used in processing liquefied natural gas (LNG) and therefore will be capable of pressurizing liquid methane from at least about 200 pounds per square inch (psi) to about 1,200 psi at a flow rate of from at least about 1,000 cubic meters per hour (m³/hr) to about 2,500 m³/hr and up to about 25,000 m³/day.

As used herein, the term “reboiler heat exchanger” refers to an indirect heat exchange means used to at least partially vaporize a stream withdrawn near the bottom of a separation unit or feed separator.

As used herein, the term “bottoms stream” or “bottoms product” refers to an at least partially liquid stream withdrawn from at or near the bottom portion of a separation unit or separation vessel.

As used herein, the terms “comprising,” “comprises,” and “comprise” are open-ended transition terms used to transition from a subject recited before the term to one or elements recited after the term, where the element or elements listed after the transition term are not necessarily the only elements that make up of the subject.

As used herein, the terms “containing,” “contains,” and “contain” have the same open-ended meaning as “comprising,” “comprises,” and “comprise.”

As used herein, the terms “distillation” or “fractionation” refer to the process of physically separating chemical components into a vapor phase and a liquid phase based on differences in the components’ boiling points and vapor pressures at specified temperature and pressure. Another type of separation may be referred to as “phase separation,” which simply allows a gas-liquid fluid to separate based on differences in the density of the two fluids, for example in a vessel, by releasing the fluid out of the bottom of the vessel and releasing the gas out of the top of the vessel without additional physical elements such as weir plates, strippers, chimneys, internal packing, etc.

As used herein, the terms “having,” “has,” and “have” have the same open-ended meaning as “comprising,” “comprises,” and “comprise.” As used herein, the terms “including,” “includes,” and “include” have the same open-ended meaning as “comprising,” “comprises,” and “comprise.”

As used herein, the term “natural gas” refers to a multi-component gas obtained from a crude oil well (associated gas) or from a subterranean gas-bearing formation (non-associated gas). The composition and pressure of natural gas can vary significantly. A typical natural gas stream contains methane (C1) as a significant component. The natural gas stream may also contain ethane (C2), higher molecular weight hydrocarbons, and one or more acid gases. The natural gas may also contain minor amounts of contaminants such as water, nitrogen, iron sulfide, wax, and crude oil.

As used herein, the term “natural gas feed stream” refers to a stream of natural gas after it has undergone at least some pretreatment, as described elsewhere in the disclosure.

As used herein, the term “nitrogen rejection unit” or “NRU” refers to any system or device configured to receive a natural gas feed stream comprising substantially methane and nitrogen and produce substantially “pure” products streams (e.g. a salable methane stream and a nearly pure nitrogen stream—about 96 to 99 percent N₂). Examples of types of NRU's include cryogenic distillation (most common), pressure swing adsorption (PSA), membrane separation, lean oil absorption, and solvent absorption.

As used herein, the term “separation unit” refers to any vessel configured to receive a fluid having at least two constituent elements and configured to produce a gaseous stream out of a top portion and a liquid (or bottoms) stream out of the bottom of the vessel. The separation unit may include internal contact-enhancing structures (e.g. packing elements, strippers, weir plates, chimneys, etc.), may include one, two, or more sections (e.g. a stripping section and a reboiler section), and may include additional inlets and outlets. Exemplary vessels include bulk fractionators, strippers, phase separators, and others.

As used herein, the term “cryogenic condition” refers to a temperature and pressure that is sufficient to liquefy a majority portion of a fluid. For a fluid containing a single component, the cryogenic condition is below the bubble point of the single component fluid. For a fluid having multiple components, the temperature and pressure may be below the bubble point of only one of the components and if the composition is such that the majority portion of the fluid is liquefied, then the fluid is under cryogenic conditions for purposes of the present disclosure.

As used herein, the term “heat exchanger” refers to any device or system configured to transfer heat energy or cold energy between at least two distinct fluids. Exemplary heat exchanger types include a co-current or counter-current heat exchanger, an indirect heat exchanger (e.g. a spiral wound heat exchanger or a plate-fin heat exchanger such as a brazed aluminum plate fin type), direct contact heat exchanger, shell-and-tube heat exchanger, or some combination of these.

Description

The disclosed systems generally disclose a rough pre-separation of a natural gas feed stream comprising nitrogen and methane and having a temperature above cryogenic conditions. The systems further include a feed stream heat exchanger configured to reduce the temperature of the natural gas feed stream to form a substantially liquefied natural gas feed stream, a separation unit configured to receive the cooled natural gas feed stream and produce an overhead stream enriched in nitrogen and a bottoms stream enriched in methane (“liquefied methane stream”), and a liquid methane pump configured to pump the liquefied methane stream to a gas sales compression pressure to form a pressurized liquefied methane stream, wherein the pressurized liquefied methane stream is substantially vaporized in the feed stream heat exchanger to form a methane product stream.

The disclosed methods generally include the steps of cooling a natural gas feed stream in a feed stream heat exchanger to form a substantially liquefied natural gas feed stream, separating the substantially liquefied natural gas feed stream in a separator to produce an overhead stream enriched in nitrogen and a liquid bottoms stream enriched in methane (“liquefied methane stream”), pressurizing the liquefied methane stream in a liquid methane pump to a gas sales compression pressure to form a pressurized liquefied methane stream, and exchanging heat from the natural gas feed stream to the pressurized liquefied methane stream in the feed stream heat exchanger to form a methane product stream.

The presently disclosed systems and methods generally disclose pre-separation of a natural gas feed stream to produce a saleable methane product stream and a nitrogen enriched stream still containing a significant amount of methane (e.g. from about 8 to about 40 percent nitrogen by volume with the remainder substantially comprising methane). The produced overhead stream enriched in nitrogen will be about 25 percent to less than 50 percent of the volume of the initial natural gas feed stream, and may then be sent to a traditional NRU to provide additional methane product. The pre-separation step further includes the use of a unique LNG pump to pump the liquefied methane stream up to pressure to provide a pressurized liquefied methane stream for heat exchange with the natural gas feed stream, where the pressurized liquefied methane stream is expanded into gaseous form and provided at high pressure and preferably without additional compression to the methane sales pipeline as a methane product stream.

In some embodiments of the systems and methods, the liquid methane pump may be a sleeve bearing type pump and may further include a magnetic thrust bearing to reduce a gravity thrust load on an axial bearing of the liquid methane pump. The separation unit may be a cryogenic separator or include a cryogenic nitrogen stripper (a staged separation device) top portion and a reboiler bottom portion. The overhead stream enriched in nitrogen may be sent to a traditional nitrogen rejection unit for additional nitrogen removal to form another methane product stream or it may be sent to a power generation unit to produce power, or some combination of both of these.

The described systems and methods can operate on any gas stream containing 5% to 25% (vol) nitrogen to remove up to 75% or more of the methane in the natural gas feed stream as a methane product stream requiring no further processing (e.g. ready for sale). The heat integration of the natural gas feed stream, the pressurized liquefied methane stream, and the overhead stream enriched in nitrogen have been carefully designed to optimize the pressure to which the liquefied methane stream can be pumped, in order to minimize the gas compression power needed to put the methane product stream into a sales pipeline. The pumping power requirement per unit of liquid methane is much less than the compression power requirement per unit of gaseous methane. Beneficial results of the disclosed systems and methods include greater equipment reliability, lower capital cost, lower operating cost, and smaller equipment footprint. In addition, the size of the NRU (Nitrogen Removal Unit) required to treat the remaining gas is significantly reduced. Many different commercially available NRU designs can be employed downstream of the cryogenic bulk Nitrogen separation process above to separate the Nitrogen from the remaining gas stream. These and other embodiments are further described in the attached figures, which are provided for illustrative purposes.

Referring now to the figures, FIG. 1 is a schematic illustration of a system in accordance with certain elements of the disclosure. The system 100 includes a natural gas feed stream 102, a feed stream heat exchanger 104 having a feed condensing pass 103, a substantially liquefied natural gas feed stream 106, a flow control element 108, a separation unit 110, a liquefied methane stream 112, a liquid methane pump 114, a pressurized liquefied methane stream 116, a methane product stream 118, and an overhead stream enriched in nitrogen 120. As shown, the pressurized liquefied methane stream 116 and the overhead stream enriched in nitrogen 120 are routed through the feed stream heat exchanger 104, where the pressurized liquefied methane stream 116 is vaporized to form a methane product stream 118 and the overhead stream enriched in nitrogen is warmed to form a warmed nitrogen enriched stream 122.

Additional elements shown in FIG. 1 include a diverted warmed nitrogen enriched stream 124 going to a compressor 126 and a compressed warmed nitrogen enriched stream 128 entering a nitrogen rejection unit (NRU) 130 to form another methane product stream 132. Alternatively or in addition, another diverted warmed nitrogen enriched stream 134 is shown going to a power generation unit 136.

The natural gas feed stream 102 is a natural gas stream that has probably undergone pretreatment to remove some of the contaminants and components from the natural gas stream. Pretreatment is generally the first consideration in cryogenic processing of natural gas. A raw natural gas suitable for the disclosed system 100 may comprise natural gas obtained from a crude oil well (associated gas) or from a gas well (non-associated gas). The composition of the natural gas can vary significantly depending on the source. Natural gas will typically contain methane (C₁) as the major component, and will typically also contain ethane (C₂), propane (C₃), and other higher hydrocarbons, diluents such as nitrogen, argon, and helium, and contaminants such as water, carbon dioxide, mercury, mercaptans, hydrogen sulfide, benzene, methanol, iron sulfide, ethylene glycol, and others. The solubilities of these contaminants vary with temperature, pressure, and composition. At cryogenic conditions, CO₂, water, and other contaminants can form solids, which can plug flow passages in cryogenic heat exchangers and other equipment. These potential difficulties can be avoided by removing such contaminants. Although requirements may vary, the following are exemplary amounts of contaminants that may be accepted in a methane product stream: water—0.1 part per million (ppm); carbon dioxide—10 to 1,000 ppm; methanol—1.0 ppm; benzene—0.1 ppm; hydrogen sulfide—50 to 500 ppm; ethylene glycol—1.0 ppm. In the following description, it is assumed that the natural gas feed stream 102 has been suitably treated to remove unacceptable levels of mercury, sulfides, carbon dioxide, and other contaminates, and dried to remove water using conventional and well-known processes (e.g. amine treating, membrane separation, adsorption, etc.) to produce a “sweet, dry” natural gas feed stream 102. Alternatively, some level of these contaminants may be left in the natural gas feed stream 102 and become distributed into the methane product stream which may require additional treatment at a later stage depending on the intended use of the methane product stream.

Although feed stream heat exchanger 104 is depicted as surrounding the separation unit 110, the heat exchanger 104 may not enclose the separation unit 110, but the system 100 may include a “cold box” (an insulation system comprising a sheet metal box filled with perlite or other appropriate insulating medium) configured to enclose the heat exchanger 104 and the separation unit 110. The feed exchanger 104 is configured to include a feed condensing pass 103 configured to condense at least a majority portion of the natural gas feed stream 102. The feed exchanger 104 is further configured to operate at pressures up to about 1,000 pounds per square inch (psi) and lower the temperature of the feed stream 102 to a temperature of from about −180° F. to about −100° F. Note that this temperature range is higher than the temperatures generally required for full cryogenic separation of the type that occurs in a standard cryogenic separation NRU. In some embodiments, the heat exchanger 104 is preferably an indirect heat exchanger such as a spiral wound heat exchanger, a plate-fin heat exchanger (e.g. a brazed aluminum plate fin type), or a printed circuit heat exchanger.

The substantially liquefied natural gas feed stream 106 produced from the heat exchanger 104 will preferably comprise from about 5 volume percent (vol %) to about 25 vol % nitrogen with the remainder being primarily methane. In addition, the natural gas feed stream 106 may have an expected flow rate of from at least about 10 million standard cubic feet per day (10 Mscf/d) to about 800 Mscf/d or more (larger amounts may require multiple systems 100 in parallel) and enter the system 100 at a pressure of from about 300 psi to about 1,000 psi.

Flow regulating device 108 can be any device or group of devices capable of regulating the flow of liquid to the separation unit 110 to maintain a desired pressure, temperature, and liquid level in the separation unit 110, such as, but not limited to, a flow control valve, a temperature control valve, a feed separator, a liquid regulator, an expansion device, a flow regulating pump, or a combination of such equipment. If the pressure of stream 106 is higher than the pressure in the separation unit 110, the flow regulating device 108 can be used to depressurize the liquid to a pressure at or near the pressure of the separation unit 110. If the pressure of the stream 106 is lower than the pressure in separation unit 110, a flow regulating pump may be used to increase the pressure of stream 106 to a pressure at or near the pressure of the separation unit 110.

The separation unit 110 may be a simple phase separator device, a bulk fractionator (e.g. distillation) type of device, a stripper column, or some combination of these. The separation unit 110 is considered a cryogenic separation unit because it will receive a majority liquefied natural gas feed stream 106 and produce a liquefied methane stream 112. In one exemplary embodiment, the separation unit 110 may be a simple cryogenic phase separator, a cryogenic stripper column having stripping internals such as weir plates, a cryogenic distillation column (also referred to as a bulk fractionation column or tower) having one, two, three or more sections with internals configured to increase the amount of contact between a falling liquid product (liquefied methane) and a rising gaseous product (overhead stream enriched in nitrogen). In another alternative embodiment, the separation unit 110 may include one inlet or more than one inlet to receive the majority liquefied natural gas feed stream 106. For example, in some embodiments, the separation unit 110 may comprise an upper stripping section and a lower reboiler section.

The separation unit 110 is configured to operate at pressures from about 200 psi to about 500 psi or from about 250 psi to about 300 psi. Such high pressures are typically not used in conventional nitrogen rejection unit designs to support a salable methane product stream. In addition, the separation unit 110 is configured to produce the liquefied methane stream 112 having less than about 4 volume percent (vol %) nitrogen or less than about 2 vol % or less than about 1 vol % nitrogen. The liquefied methane stream 112 is further configured to be at a pressure from about 200 psi to about 600 psi or from about 300 psi to about 500 psi and a temperature of from about −300 degrees Fahrenheit (° F.) to about −100° F. or from about −280° F. to about −160° F. These compositions, pressures, and temperatures may be adjusted depending upon process economics, requirements of a methane sales contract, flow rate, pressure, and composition of the natural gas feed stream 102, and other factors that can be adjusted for by a person of ordinary skill in the art.

In one exemplary embodiment, the separation unit 110 is configured to produce the overhead stream enriched in nitrogen 120 having from about two times to about four times the concentration of nitrogen in the natural gas feed stream 102, depending on the amount of nitrogen removal required. The overhead stream enriched in nitrogen 120 is further configured to be at a pressure from about 100 psi to about 500 psi or from about 200 psi to about 400 psi and a temperature of from about −300 degrees Fahrenheit (° F.) to about −100° F. or from about −280° F. to about −160° F. These compositions, pressures, and temperatures may be adjusted depending upon process economics, requirements of a methane sales contract, flow rate, pressure, and composition of the natural gas feed stream 102, and other factors that can be adjusted for by a person of ordinary skill in the art.

In one exemplary configuration, the separation unit 110 is configured to provide overhead stream enriched in nitrogen 120, which may be sent to a conventional NRU 130, a power generation unit 136, or some combination thereof. The nitrogen to methane ratio in the overhead stream enriched in nitrogen 120 is important for providing adequate cryogenic reflux in the NRU 130 to ensure high methane product recovery in the NRU 130. The separation unit 110 may also be configured to separate from the natural gas feed stream 102 a liquefied methane stream 112 that meets sales pipeline requirements and reduces, to the greatest extent possible, the size of the overhead stream enriched in nitrogen 120 to the NRU 130. Beneficially, the smaller the overhead stream enriched in nitrogen 120, the smaller the NRU 130 and its associated compression requirements.

The liquid methane pump 114 is preferably a sleeve bearing type pump configured to pump the liquefied methane stream 112 to a gas sales compression pressure to form a pressurized liquefied methane stream 116. Canned motor pumps are more fully disclosed in U.S. Pat. No. 4,890,988, which is hereby incorporated by reference for purposes of describing canned motor pumps. In general, a canned motor pump includes two coaxial tubular walls defining an annular space for the flow of a heat exchange fluid which heats or cools the can. In addition, sleeve bearing pumps may prove to be more reliable than the currently used roller bearing pumps. These sleeve bearing pumps are capable of reliable long life from the radial and axial sleeve bearings. A significant contribution to the axial thrust bearing long life is a magnetic thrust bearing compensation device which reduces the gravity thrust load on the axial bearing during starting. This reduction in axial thrust load allows the hydrodynamic thrust bearing to build the lubricant film, or lift off quicker, reducing direct frictional contact during startup acceleration. Operationally, the pumps will experience flow variations from near zero to maximum (e.g. up to about 25,000 m³/day) rating during cool-down, startups and upset conditions. Similarly, the pressures can vary from near atmospheric to rated conditions (e.g. up to about 1,000 psi). Frequent starting and stopping of these pumps is sometimes required based on feed gas availability. It is believed that no prior art system incorporates these types of pumps for LNG operations. Further, persons skilled in the art prefer not to pump LNG at such high pressures and flow rates due to known reliability issues with the bearings in cryogenic pumping operations at such elevated pressures and flow rates. See, e.g. COYLE, DAVID A., PATEL, VINOD, Processes and Pump Services in the LNG Industry, Proceedings of the Int'l Pump Users Symposium (2005).

The liquid methane pump 114 is preferably configured to pump a fully liquefied or nearly fully liquefied methane stream 112 from a pressure of from a pressure of about 200 psi to about 600 psi up to a pipeline pressure of from about 400 psi to about 1,000 psi, at flow rates (per pump for multiple pump systems) from at least about 1,000 m³/hr to about 5,000 m³/hr or from about 1,500 m³/hr to about 3,000 m³/hr (over a day, these rates may be from about 10,000 m³/day to about 30,000 m³/day) depending on the requirements of the pipeline and the methane sales contract.

FIG. 2 is a flow chart illustrating of a process in accordance with certain aspects of the system of FIG. 1. As such, FIG. 2 may be best understood with reference to FIG. 1. The process 200 includes box 202 showing the step of cooling a natural gas feed stream 102 in a feed stream heat exchanger 104 to form a substantially liquefied natural gas feed stream 106 and box 204 showing the step of separating the substantially liquefied natural gas feed stream 106 in a separator unit 110 to produce an overhead stream enriched in nitrogen 120 and a liquid bottoms stream enriched in methane (“liquefied methane stream”) 112. The process 200 further includes box 206 showing the step of pressurizing the liquefied methane stream in a liquid methane pump 114 to a gas sales compression pressure to form a pressurized liquefied methane stream 116 and box 208 showing the step of exchanging heat from the natural gas feed stream 102 to the pressurized liquefied methane stream 116 in the feed stream heat exchanger 104 to form a methane product stream 118.

The process may further include pretreating steps (not shown) as described in connection with the system 100. The process 200 may also include feeding at least a portion of the overhead stream enriched in nitrogen 120 to the feed stream heat exchanger 104 to form a warmed nitrogen enriched stream 122, compressing the warmed nitrogen enriched stream in a compressor 126 to form a compressed nitrogen enriched stream 128, which is fed to a nitrogen rejection unit (NRU) 130 to form a methane enriched stream 132, which may be sold as a methane product stream.

FIGS. 3A-3C are schematics of several exemplary alternative embodiments of the system of FIG. 1. As such, FIGS. 3A-3B may be best understood with reference to FIG. 1. In FIG. 3A, to the extent an element in system 300 is designated with the same reference number as system 100, that element may be considered to be equivalent to or substantially equivalent to the element as described above in connection with system 100. The system 300 further includes a flow control device 302, a pressure control device 303, a controlled flow stream 306 flowing into a feed separator 308 configured to produce a nitrogen enriched gas stream 312 and a bottoms stream enriched in methane 310, which passes to the separator unit 110 via a level control device 311. The separator unit 110 is configured with a top feed stripper portion 314 and a lower cryogenic reboiler portion 316 to reduce the nitrogen content of the liquefied methane stream 112. The system 300 further includes a reboiler stream 324 from the reboiler portion 316 of the separation unit 110 and a slip stream 320 from the substantially liquefied natural gas feed stream 106, wherein the slip stream 320 and reboiler stream 324 are configured to flow through a reboiler heat exchanger 322 configured to exchange cold energy from the reboiler stream 324 to the slip stream 320. Nitrogen enriched gas stream 312 is configured to combine with the overhead stream enriched in nitrogen 120 and flow through overhead flow control valve 326 to the heat exchanger 104.

The top feed stripper 314 and reboiler 316 are configured to significantly increase the fraction of the methane in the natural gas feed stream 102 that is removed to the liquefied methane stream 112. Such removal beneficially significantly reduces the size of the NRU 130 required and further enriches the overhead stream enriched in nitrogen 120 by combining the nitrogen enriched gas stream 312 therewith, which increases methane recovery in the NRU 130 with less methane loop or nitrogen recycle compression.

The flow control device 302 may be a low pressure drop temperature control valve configured to increase or decrease the flow of the majority liquefied natural gas feed stream 106 into the slip stream 320 depending on the actual temperature of the majority liquefied natural gas feed stream 106 and the desired temperature of the controlled flow stream 306. For example, if the temperature of the controlled flow stream 306 is higher than desired, the flow control device 302 may be adjusted to restrict flow therethrough, which will increase the flow of the slip stream 320, which passes through reboiler heat exchanger 322 where it is cooled by indirect heat exchange with reboiler stream 324 and is then combined with controlled flow stream 306. Automatic or manual control may be utilized to control the flow rates of the various streams.

The feed separator 308 is configured to accumulate fluids and release a gaseous enriched nitrogen stream 312 and a liquid bottoms stream 310, which is controlled by a level control device 311. In one embodiment, the level control device 311 is a low pressure drop valve configured to maintain a particular fluid level in the feed separator 308 for continuous operation. Beneficially, this arrangement provides for higher nitrogen concentrations in the overhead stream enriched in nitrogen 120, a slightly higher methane concentration in liquid bottoms stream 310, and a slightly lower pressure and temperature in the separation unit 110.

The overhead flow control valve 326 may be a high pressure drop pressure control valve configured to maintain and control the pressure and flow rate of the overhead stream enriched in nitrogen 120.

FIG. 3B schematically illustrates an exemplary system 350, which is a modification to the systems 100, 300 to provide additional flow control options. As shown, gaseous enriched nitrogen stream 312 may be controlled by pressure control valve 352 to form controlled nitrogen stream 354, which may be combined with overhead stream enriched in nitrogen 120 to form overhead stream 356. Beneficially, such an arrangement provides greater control over the stream 356 prior to introduction into the feed stream heat exchanger 104 as well as controlling pressure in the feed separator 308.

FIG. 3C schematically illustrates an exemplary system 370, which is a modification to the systems 100, 300, 350 to provide yet more additional flow control options. In particular, system 370 shows a temperature integrated controller 372 configured to obtain a temperature of the controlled flow stream 306 and operatively connected to flow control device 302 and slip stream flow control device 378. Also shown is a flow integrated controller 374 configured to obtain a pressure of the majority liquefied natural gas stream 106 and operatively connected to at least flow control valve 376. Note, the pressure integrated controller 374 may also control the level control device 311 and the back-pressure control valve 352. Optionally, a feed pressure controller 382 and feed flow controller 384 may be provided.

Beneficially, the temperature integrated controller 372 may be configured to provide a more finely tuned temperature control of the controlled flow stream 306 by operating temperature control valves 302 and 378 in concert depending on the actual temperature of the majority liquefied natural gas feed stream 106 and the desired temperature of the controlled flow stream 306.

Still referring to FIG. 3C, the system 370 may be configured to flow-control the majority liquefied natural gas feed stream 106 downstream of the feed stream heat exchanger 104 using either the flow control device 376 or the level control device 311 or a combination of these to hold the design back-pressure on the feed condensing pass 103 of the feed stream heat exchanger 104. In particular, the flow integrated controller 374 can be used to override the flow control device 376 output in order to maintain the desired minimum back-pressure in the feed condensing pass 103 of the feed stream heat exchanger 104. Note that pressure and flow readings may be taken at stream 102, such as by a pressure sensing device sending information to feed pressure controller 382 to establish a set-point, which may be sent to feed flow controller 384, which may additionally obtain flow readings from a flowmeter or other sensor to provide a set-point to the flow control device 376. Alternatively or additionally, readings may also be taken from stream 106 and used to set the flow control device 376. The flow integrated controller 374 can operate in cascade mode or in automatic flow control mode, which is often used during cooldown and startup or during turndown (low feed flow) operation. In this mode of operation, the level control device 311 is a low pressure drop valve, and the back-pressure on the feed separator 308 and separation unit 110 can be controlled with a common low-pressure drop control valve.

In another exemplary alternative embodiment, the system 370 can operate without the feed separator 308, level control device 311, and back-pressure control valve 352. In such an arrangement, the pressure control functions are all accomplished using the flow control device 376, which is a high pressure drop expansion valve, such as a Joule-Thompson type unit.

The flow control device 376 can also be configured to operate independently of the pressure control function by using the back-pressure control valve 352 to increase the operating pressure of the feed separator 308 and using level control device 311 as the primary liquid expansion device (e.g. a Joule-Thompson type valve). Note that the back-pressure control valve 352 would operate as a vapor expansion device in this case. In this embodiment, the top feed separator 308 is provided, and the feed separator 308 operates at the same pressure as the feed condensing pass 103 in the feed exchanger 104. The temperature control valve 302 is a low pressure drop valve and the feed separator back pressure control 352 and level control valve 311 are both high pressure drop valves. As such, at least part of the feed expansion device operation takes place across these two separator control valves.

FIG. 4 illustrates a chart showing a temperature heat flow plot for comparing heat flow between hot and cold streams. The chart 400 plots temperature in degrees Fahrenheit (° F.) along the y-axis 402 and heat flow in millions of British thermal units per hour (MBtu/hr) along the x-axis 404. A curve for a warm fluid (about 900 psi) flowing through a heat exchanger is shown at 406, a curve for a lower pressure (about 300 psi) cold fluid flowing through the heat exchanger is shown at 408, and a curve for a higher pressure (about 775 psi) cold fluid flowing through the heat exchanger is shown at 410. In T-Q charts such as chart 400, the important factor is the gap between the warm fluid curve 406 and the cold fluid curves 408 or 410. As shown, the gap between the warm fluid curve 406 and the high pressure cold fluid curve 410 maintains about a 5-10 degree difference through the charted temperature range of about −130° F. to about 130° F. This means that there is heat transfer between these two fluids, even at the higher pressures. There is a slightly higher rate of heat transfer between the warm fluid 406 and the lower pressure cold fluid 408 than between the warm fluid 406 and the high pressure cold fluid 410, but for the purposes of the disclosure, the heat transfer is sufficient to meet the requirements of the process.

Beneficially, keeping the fluid at a higher pressure reduces or eliminates the need to repressurize the product gas for pipeline delivery, which eliminates a portion of the horsepower, footprint, and materials needed for compression of the lower pressure stream. This process efficiency more than makes up for the slight decrease in heat transfer efficiency shown by the T-Q chart 400.

EXAMPLE

In one exemplary case, a natural gas feed stream having an assumed temperature, flow rate, pressure, and composition was provided. Table 1 below shows the temperature, flow rate, pressure, and composition of the relevant streams as shown in FIGS. 1 and 3A.

TABLE 1 Stream Stream Stream Stream Stream Stream Stream Stream Component 102 122 118 106 306 112 120 312 methane 0.904 0.775 0.977 0.904 0.904 0.965 0.781 0.773 nitrogen 0.093 0.224 0.020 0.093 0.093 0.032 0.219 0.227 ethane 0.003 0.001 0.003 0.003 0.003 0.003 0.000 0.000 Total 1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000 Pressure 915 275 770 905 902 285 280 300 (psia) Temperature 136 130 130 −131 −150 −170 −176 −174 (deg F.) Mscfd 95 34 61 95 95 77 16 18

In particular, the exemplary flow rates illustrate the relative size of warmed nitrogen rich stream 122 as compared with the natural gas feed stream 102. Beneficially, this results in a smaller volume of fluids going to the NRU 130 for further treatment, lowering the energy consumption, footprint, materials, and capital costs of such systems and methods as disclosed herein. It is also worth noting the difference in pressure between stream 112 and 118. This pressure increase is preferably obtained through pumping stream 112 up to pressure rather than using compression equipment, which provides still more savings in energy use and equipment cost as well as potentially providing greater reliability.

While the present disclosure may be susceptible to various modifications and alternative forms, the exemplary embodiments discussed above have been shown only by way of example. However, it should again be understood that the disclosure is not intended to be limited to the particular embodiments disclosed herein. Indeed, the present disclosure includes all alternatives, modifications, and equivalents falling within the true spirit and scope of the appended claims. 

What is claimed is:
 1. A nitrogen rejection system, comprising: a natural gas feed stream comprising nitrogen and methane and having a temperature above cryogenic conditions; a feed stream heat exchanger configured to reduce the temperature of the natural gas feed stream to form a majority liquefied natural gas feed stream; a separation unit configured to receive the cooled natural gas feed stream and produce an overhead stream enriched in nitrogen and a bottoms stream enriched in methane (“liquefied methane stream”); and a liquid methane pump configured to pump the liquefied methane stream to a sales compression pressure to form a pressurized liquefied methane stream, wherein the pressurized liquefied methane stream is substantially vaporized in the feed stream heat exchanger to form a methane product stream.
 2. The system of claim 1, wherein the liquid methane pump is a sleeve bearing type pump.
 3. The system of claim 2, wherein the liquid methane pump comprises a magnetic thrust bearing configured to reduce a gravity thrust load on an axial bearing of the liquid methane pump.
 4. The system of claim 3, wherein the configuration of the sleeve bearing type pump is selected from the group consisting of: a single pump, a series of at least two pumps, a parallel configuration of at least two pumps, a multistage pump, and any combination thereof.
 5. The system of claim 3, wherein the separation unit is configured to operate at a pressure of at least about 200 pounds per square inch (psi) to about 500 psi and a temperature of at least about −220 degrees Fahrenheit (° F.) to about −120° F.
 6. The system of claim 5, wherein the separation unit is a tower having a top feed stripper portion and a lower cryogenic reboiler portion configured to separate gaseous nitrogen from the liquefied methane stream.
 7. The system of claim 5, wherein at least a portion of the overhead stream enriched in nitrogen is fed to the feed stream heat exchanger to form a warmed nitrogen enriched stream.
 8. The system of claim 7, further comprising: a compressor configured to compress the warmed nitrogen enriched stream to form a compressed nitrogen enriched stream; and a nitrogen rejection unit (NRU) configured to receive the compressed nitrogen enriched stream to form a methane enriched stream.
 9. The system of claim 8, wherein the warmed nitrogen stream is less than about 50 volume percent (vol %) of the natural gas feed stream.
 10. The system of claim 5, wherein at least a portion of the overhead stream enriched in nitrogen is fed to a power generation unit configured to generate power using the at least a portion of the overhead stream enriched in nitrogen.
 11. The system of claim 5, further comprising: a reboiler feed stream from the separation unit; a slip stream from the substantially liquefied natural gas feed stream; and a reboiler heat exchanger configured to exchange heat energy from the slip stream to the reboiler feed stream to generate a nitrogen containing vapor from the reboiler feed stream, wherein the slip stream is then re-mixed with the substantially liquefied natural gas feed stream.
 12. The system of claim 11, further comprising an expansion device configured to receive the substantially liquefied natural gas feed stream and hold a back-pressure on a feed condensing pass of the feed stream heat exchanger, wherein the expansion device is selected from the group consisting of a flow control device, a level control device, a back-pressure control valve, and any combination thereof.
 13. The system of claim 11, further comprising: a feed separator configured to produce a nitrogen enriched gas stream and a bottoms stream enriched in methane; and at least one level control valve configured to maintain a liquid level in the feed separator.
 14. The system of any one of claims 12-13, further comprising a flow integrated controller configured to control at least the back-pressure on the feed condensing pass of the feed stream heat exchanger.
 15. A method of nitrogen rejection, comprising: cooling a natural gas feed stream comprising nitrogen and methane in a feed stream heat exchanger to form a majority liquefied natural gas feed stream; separating the substantially liquefied natural gas feed stream in a separator to produce an overhead stream enriched in nitrogen and a liquid bottoms stream enriched in methane (“liquefied methane stream”); pressurizing the liquefied methane stream in a liquid methane pump to a sales compression pressure to form a pressurized liquefied methane stream; and exchanging heat from the natural gas feed stream to the pressurized liquefied methane stream in the feed stream heat exchanger to form a methane product stream.
 16. The method of claim 15, wherein the liquid methane pump is a sleeve bearing type pump.
 17. The method of claim 16, wherein the liquid methane pump comprises a magnetic thrust bearing configured to reduce a gravity thrust load on an axial bearing of the liquid methane pump.
 18. The method of claim 17, wherein the configuration of the sleeve bearing type pump is selected from the group consisting of: a single pump, a series of at least two pumps, a parallel configuration of at least two pumps, a multistage pump, and any combination thereof.
 19. The method of claim 17, wherein the separation unit is configured to operate at a pressure of at least about 200 pounds per square inch (psi) to about 500 psi and a temperature of at least about −220 degrees Fahrenheit (° F.) to about −120° F.
 20. The system of claim 19, wherein the separation unit is a tower having a top feed stripper portion and a lower cryogenic reboiler portion configured to separate gaseous nitrogen from the liquefied methane stream.
 21. The method of claim 19, further comprising feeding at least a portion of the overhead stream enriched in nitrogen to the feed stream heat exchanger to form a warmed nitrogen enriched stream.
 22. The method of claim 21, further comprising: compressing the warmed nitrogen enriched stream in a compressor to form a compressed nitrogen enriched stream; and feeding the compressed nitrogen enriched stream to a nitrogen rejection unit (NRU) to form a methane enriched stream.
 23. The method of claim 22, wherein the warmed nitrogen stream is less than about 50 volume percent (vol %) of the natural gas feed stream.
 24. The method of claim 19, further comprising: feeding at least a portion of the overhead stream enriched in nitrogen to a power generation unit; and generating power in the power generation unit.
 25. The method of claim 19, further comprising: taking a reboiler feed stream from the separation unit; taking a slip stream from the substantially liquefied natural gas feed stream; exchanging heat energy from the slip stream to the reboiler feed stream in a reboiler heat exchanger to generate a nitrogen containing vapor from the reboiler feed stream; and re-mixing the slip stream with the substantially liquefied natural gas feed stream.
 26. The method of claim 25, further comprising: maintaining a back-pressure on a feed condensing pass of the feed stream heat exchanger using an expansion device configured to receive the substantially liquefied natural gas feed stream, wherein the expansion device is selected from the group consisting of a flow control device, a level control device, a back-pressure control valve, and any combination thereof.
 27. The method of claim 25, further comprising: producing a nitrogen enriched gas stream and a bottoms stream enriched in methane in a feed separator; and maintaining a liquid level in the feed separator using a level control valve.
 28. The method of any one of claims 26-27, further comprising controlling at least the back-pressure on a feed condensing pass of the feed stream heat exchanger and the back-pressure on the separation unit using flow integrated controller.
 29. The nitrogen rejection system of claim 1, wherein the liquefied methane stream comprises ethane and heavier hydrocarbons.
 30. The method of nitrogen rejection of claim 15, wherein the liquefied methane stream comprises ethane and heavier hydrocarbons. 